June 16, 2006
By EDGAR and by fax (202) 772-9369
Mr. H. Roger Schwall
Assistant Director
Division of Corporation Finance
United States Securities and Exchange Commission
100 F Street, N.E.
Washington, D.C.
20549-7010
| Re: | Letter dated June 2, 2006 to St. Mary Land & Exploration Company | |||
| Form 10-K for the fiscal year ended December 31, 2005 |
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| Filed February 27, 2006 |
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| File No. 1-31539 |
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Dear Mr. Schwall:
Please find our response to the above captioned comment letter dated June 2, 2006. As a courtesy, we have reproduced the applicable portion of the letter in our responses. The comments are in bold text and our responses are incorporated within the document in normal text.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 2
1. | In response to your response number 3 please provide the technical evidence that supports the attribution of proved undeveloped reserves more than one offset location away from a producing location in your coal bed methane properties. Please include a map showing the proved undeveloped locations in question, the location of the water monitoring wells; the location of the nearest producing wells with their current gas and water production rates, and their cumulative gas and water production; the pressure changes over time in the field as determined by the water monitoring wells and any other information you deem relevant. We may have further comments. |
The requested technical documentation that supports the attribution of proved undeveloped reserves more than one offset location away from a producing location in our coal bed methane properties has been supplementally submitted to Mr. James Murphy of the Staff.
2. | Regarding response number 4, included in Revisions of previous estimates should be reserves added through development drilling due to the approval of decreased spacing within a field. In the Extensions and discoveries category, only include reserves from past drilling that extend the limits of a previously proved reservoir, reserves from the discovery of new fields with proved reserves or a new reservoir in an old field. Please confirm to us that your reserves additions meet these criteria. |
The point we were trying to articulate in our prior response is that the language in paragraph 11 of SFAS No. 69 distinguished between the two categories based on one important concept. This concept is that for an item to be included in the revision line it has to have been previously included in the proved reserves. We were attempting to communicate that the reserves we have classified as an Extension and discovery are new proved reserves that have been added to our proved reserve database. Definitionally, the word extension matches much more closely with the reality of how we are recording proved reserves. If we believed that the reserves qualified for a proved classification in a prior period, then in a subsequent period any change would be recorded to this Revisions line item. The fact however is that the reserves we have included in the Extension and discovery line are new reserves that have been added.
We do not believe that the FASB definition states nor implies that only reserves from development drilling are classified in the Revision line, nor do we believe that the FASB implies that only the results from exploratory drilling activities should be classified in the Extension and discovery line. Accordingly, we believe that the final classification or reserves requires the use of management judgment and we believe our presentation is accurate and does not require revision.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 3
3. | Regarding response number 5, we are still considering your response. |
We note the Staff’s comment.
4. | As to response number 6, please provide the independent petrophysical evaluation, geological mapping and decline curve analysis that you state Ryder Scott generated as part of their evaluation. Also provide the Ryder Scott reserve report and the properties and the reserves for each party where significant variances existed between the company's numbers and the third party engineer's estimate. |
As discussed with Mr. James Murphy in a telephone conference on June 14, 2006, we do not require that Ryder Scott formalize their analysis in a bound report for the reserves that they prepare. Summaries of the requested technical information have been supplementally submitted to Mr. Murphy.
5. | Confirm to us that all of your proved undeveloped locations in both 2004 and 2005 complied with the existing field rules for their respective fields at the time they were booked as proved reserves. |
Some well locations in both Oklahoma and Louisiana that are included as Proved Undeveloped Reserves in our 2004 and 2005 reserve reports did not have approval from the appropriate regulatory agencies for certain increased density applications or alternate well unit designations for certain of these proved undeveloped locations at the time of publishing the reserves.
We note that in making the decision as whether or not to include these well locations in our yearend reserve disclosures we considered the location of the wells, our history of development in the specific area, the history of regulatory approval in the specific area, we polled other operators in the area, we considered our ability and intent to drill the location and we considered the applicable guidance of the SEC staff. All of these considerations led us to the conclusion that these specific well locations should be included in our yearend reserves. The SEC Staff guidance we are referring to was issued on February 21, 2001, and is set forth under Item II.F.3 of the Division of Corporation Finance’s Requested Accounting and Financial Reporting Interpretations and Guidelines on the SEC’s website, as shown below:
Issue 3. d. Paragraph 4 – The history of issuance and continued recognition of permits, concessions and commerciality agreements by regulatory bodies and governments should be considered when determining whether hydrocarbon accumulations can be classified as proved reserves. Automatic renewal of such agreements cannot be expected if the regulatory body has the authority to end the agreement unless there is a long and clear track record which supports the conclusion that such approvals and renewal are a matter of course.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 4
Based on our observed long and clear track record of receiving approval of increased density applications from the regulatory agencies described below, we believe there is only a remote possibility that these locations will not be approved and drilled by the Company, accordingly, we believe the classification of these reserves as Proved Undeveloped Reserves was appropriate in each respective reserve report. The specifics of these particular well locations are described below.
At Elm Grove Field in Louisiana, our research has indicated that 100 percent of alternate unit designations have been approved by the Louisiana Office of Conservation allowing for 40 acre drilling density. Over 200 alternate well unit applications were obtained in 2005 by the operators of our Elm Grove Field leases with no denied applications. We have consulted specialists who focus on alternate well unit applications in Louisiana, who have confirmed 100% approval of over 300 applications per year since 1985 in various fields in Louisiana. We have operated in Louisiana since 1992 and 100 percent of our applications for alternate well unit designations have been approved by the Louisiana Office of Conservation. Given this long and clear track record of approvals in the area we are drilling as well as our observed history of obtaining these approvals, we concluded that the classification of our PUD reserves at Elm Grove Field and other Louisiana fields on well locations that are adjacent to productive wells is appropriate. Although our ownership in Elm Grove Field dates back only to December 2004 when we acquired our interests in the field, our experience to date has been consistent and we have no reason to believe it will not continue.
Similarly, our evaluation of increased density applications with the Oklahoma Corporation Commission has yielded similar approval history. Specifically, from 1998 through 2003, our research concluded that 97% of the increased density applications in Beckham (NE Mayfield) and Coal (Centrahoma) Counties were approved. Since 2003, 100% of St. Mary’s increased density applications have been approved. The PUD well locations for these areas are adjacent to productive wells in the associated field. As a company, we have had operations in Oklahoma for over 15 years and our Mid-Continent region has been the most active drilling region of our Company. As such, our experience with these regulatory matters is extensive. With our expertise, history and the realized results of the regulatory approval process, we have concluded that the classification of the reserves associated with these well locations as Proved Undeveloped is appropriate.
6. | Regarding response number 8 please provide the fields, the quantity of net proved reserves you attributed to each field and under which criteria in the FASB 69 reserve reconciliation table you attributed the reserves to down spacing of drilling locations that had not yet been approved in each of the years 2004 and 2005. We may have further comments. |
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 5
This comment response should be read in conjunction with response number 2 and response number 5. The table below has been supplementally provided to the Staff in response to the comment. The table presents a summary of the reserves as well as the PV-10 value included in each year that were subject to down spacing approval. As described in response number 2 and response number 5, we believe that the inclusion of these reserves in each year’s reserve disclosures is appropriate and we believe that the classification as an Extension and discovery is also appropriate.
Reserve added and the associated PV-10 are as follow ($’s in millions):
| 2004 | 2005 |
| BCFE | PV-10 | BCFE | PV-10 |
| Centrahoma Field, OK | 0.9 | $ 0.6 | 20.3 | $31.8 | |||||||||
| NE Mayfield Field, OK | 2.9 | 3.4 | 0.9 | 0.3 | |||||||||
| Middleburg Field, OK | 1.1 | 1.4 | - | - |
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| Elm Grove Field, LA | - | - | 25.6 | 39.5 | |||||||||
| Spider Field, LA | - | - | 3.9 | 14.3 | |||||||||
| Field Totals | 4.8 | $ 5.3 | 50.6 | $85.8 | |||||||||
| Percent of St. Mary Totals | 0.7% | 0.4% | 6.4% | 3.4% |
7. | We note that in the last three years you have averaged $47 million per year in exploration costs and $184 million per year in development costs. We also note that in the reserve report for 2005 you identify a total of $171 million in development costs. However, in your 10-K you indicate that your 2006 drilling budget has been increased to $500 million. This suggests that about two-thirds of the 2006 drilling budget will be for more risky drilling in unproved areas. Please advise or revise your document to include this information. |
The magnitudes of the numbers you point out have not been much different for St. Mary from year to year. The following table reflects the initial total proved capital development costs for the ensuing year and the initial capital budget for the corresponding year. The derived percentage is recalculated.
| 2004 | 2005 |
Undiscounted capital per the reserve report (millions) | $ | 76 | $ 171 |
Capital budget for the related year (millions) | $ 293 | $ 500 | |
Derived percentage | 25.9% | 34.2% |
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 6
Our capital budgeting process includes anticipated capital spending that includes Proved Developed Non Producing, Proved Undeveloped, Probable and Possible reserves. Often times in the period between reporting yearend reserves we will develop a Proved Undeveloped location that will allow us to move Probable or Possible locations into the Proved category during the year. Our budget process has historically included the capital costs associated with these Probable and Possible locations. Our capital budget process also contemplates forecasts of costs that we expect to be paying based on industry trends of service, equipment, chemical and personnel costs over the ensuing period, rather than being based solely on the costs in effect as of yearend, as reflected in the reserve case published in the Form 10-K.
As a Company, our business has been predominately related to development activity and in our budgeting activity we contemplate the success we expect to achieve in our drilling results and may include activities in our budget that are more than one offset location away, as mentioned earlier. Our success ratio from drilling has been 93.5 percent, 88.2 percent, and 82.5 percent in 2005, 2004 and 2003, respectively. Through the first quarter of 2006, our success ratio has been 89.9 percent, including recompletions and 98 percent on conventional wells, excluding recompletions.
We believe that this information supports that our risk profile is consistent with our disclosures that “we have assembled a balanced program of low-to-medium-risk development and exploitation projects that provide the foundation for steady growth”
As such, we do not believe that supplemental disclosure is necessary. In the event that St. Mary does change its focus to higher risk projects that would generally be characterized more as wildcat exploration, we will appropriately include disclosure in our filings at such time.
8. | Tell us if all of the proved undeveloped wells in your 2004 and 2005 reserve reports met your internal corporate investment hurdle rates or criteria for each of those years. |
Supplementally, we confirm to the Staff that all of the proved undeveloped wells in our 2004 and 2005 reserve reports meet or exceed our internal investment hurdle rates and we intend to invest to develop these reserves.
The Proved Undeveloped reserves in the 2004 and 2005 reserve reports are economic based on the cash flow models and produce a positive return on investment.
9. | Reconcile for us the fact that you have attributed 50 MMCF of proved producing reserves to the Fontana 1-27 well in Pittsburg County, OK but for the 12 proved undeveloped wells in Pittsburg County you have attributed anywhere from six to ten times the amount of proved reserves per well. Tell us the cumulative production from the Fontana 1-27 from the coal bed completion as of December 31, 2005. |
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 7
In response to Comments #9 and #10, please note that St. Mary owns an interest in numerous wells in Pittsburg County, OK and that the Fontana 1-27 well is not used in the justification of our CBM PUD reserves, as it is in a different field and produces from a conventional reservoir, the Wapanucka formation. We realize that confusion has been created by utilizing the field name of Pittsburg County CBM Gas Area for the CBM PUD locations. The field names associated with producing wells are Featherston, NW Quinton, NE Blocker and Liberty West, all located in Pittsburg County, Oklahoma. Technical reserve report information regarding the wells in these fields has been supplementally submitted to Mr. Murphy.
10. | Reconcile for us that in Pittsburg County, OK you have one well with proved producing reserves but have booked 12 proved undeveloped reserves with proved reserves. |
Please note the response to comment #9 that documents the justification for booking the proved undeveloped CBM reserves in Pittsburg County, Oklahoma.
11. | For the 18 proved undeveloped wells in the Carthage field we note the average gas reserve volume you have attributed to each well. Tell us the cumulative production through December 31, 2005 of each of the 5 wells that have proved producing reserves. Provide us with the assurance you received from the operator that the proved undeveloped wells will be drilled. |
Technical information regarding producing wells in the Carthage Field and directly offsetting productive wells in which St. Mary holds no ownership interest has been supplementally submitted to Mr. Murphy. These offsetting producers are not included in our 12/31/05 Reserve Report. To date we have received and approved 2 AFE’s to drill new wells on the property and locations for those wells have been built. Drilling operations are expected to commence in the 3rd quarter of 2006.
12. | We note that your have attributed almost twice the reserves per well to the proved undeveloped reserves in the Centrahoma field in 2005 compared to 2004. Please provide the technical reasons for attributing these increased reserves to each proved undeveloped location from that attributed the previous year. |
We successfully drilled and completed horizontal wells in the Cromwell and Woodford formations during 2005. This drilling success illustrates that horizontal completion techniques provide a more efficient method to recover reserves from these formations. Our 2004 reserve report includes Proved Undeveloped cases for 12 vertical Cromwell wells (750 mmcfe gross EUR) and 5 vertical Woodford wells (500 mmcfe Gross EUR). Our 2005 reserve report includes Proved Undeveloped cases for 21 horizontal Cromwell wells (1,515 mmcfe EUR) and 6 horizontal Woodford wells (783 mmcfe Gross EUR).
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 8
13. | Please explain to us why you increased the probable and possible reserves in the Centrahoma field so dramatically in the 2005 reserve report as compared to the 2004 report. |
In addition to the successful horizontal wells that were drilled and completed in 2005, we conducted a comprehensive study of our Centrahoma Field area assets during 2005 based on our successful horizontal tests. We concluded that significant additional potential existed. Geologic information indicated that the Cromwell, Woodford and Wapanucka formations were prospective over a broad area and conducive to application of horizontal completion techniques. We determined that these locations met the criteria of Probable and Possible resources. Additionally, we identified a structural feature on our leasehold with probable reserve potential that was included in our 2005 report.
14. | We note over 200 proved undeveloped wells in the Elm Grove field. Tell us how many wells you drilled in each of the last three years in this field. Tell us if the field rules allow for an increase in the number of wells of this magnitude in the field. Provide us with the assurance you received from the operator that these wells will be drilled. |
We acquired our position in Elm Grove Field in the fourth quarter 2004. Thus, we did not participate in the drilling and completion of wells in the field in 2003 and early 2004. However, on the leases that we acquired in Elm Grove Field, wells drilled and completed in the past three years are summarized as follows:
| 2003 | 25 wells |
| 2004 | 35 wells |
| 2005 | 40 wells |
In the first five months of 2006, we have participated in drilling and completion operations on 25 wells, with 12 completed, 8 in various stages of completion, and 5 currently drilling on our leasehold. Through meetings with the operators and as evidenced by the continued drilling commitment that these operators have demonstrated, we are confident that these wells will be drilled, which justifies our classification of these as Proved Undeveloped reserves. Additionally, with the recent acquisition activity in the field, the pace of development has increased over the years.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 9
As previously described in response #5, statewide spacing in Louisiana is one well per section. Any additional well drilled in that section requires an exception from the Louisiana Office of Conservation allowing for additional wells to be drilled with an alternate well unit designation. For the majority of Elm Grove Field, drilling density has been established at 40 acres per well. We have consulted with the operators of our leases and with attorneys that specialize in obtaining alternate unit well designations. In 2005, over 200 alternate well unit applications were obtained, with no denied applications, by the operators of our leases. We have not been able to identify a single instance in this field area where an exception has not been granted. We have concluded that, due to the long and clear track record of approval of alternate well unit designations, the classification of the reserves associated with these well locations as Proved Undeveloped is appropriate.
15. | Tell us the average economic ultimate recovery per proved producing well in the Big Sand Draw field. |
Big Sand Draw estimated ultimate recovery exceeds 56.8 MMBO from the Tensleep and Basal Phosporia formations. Thus, economic ultimate recovery averages 1,671 MBO per well for the thirty-four productive wells.
16. | We note the reserve volumes that you have attributed as proved undeveloped net reserves to the Parkway Unit A&B and 5 infill proved undeveloped wells. Tell us when these were first booked as proved and under which criteria you placed these reserves in the reserve reconciliation table when originally booked. |
St. Mary first booked the referenced Proved Undeveloped reserves in 2002. Because these reserves were related to the expansion of the pre-existing Parkway Delaware Unit Waterflood, these reserves were considered revisions.
17. | We note the gas reserves attributed to the Paggi-Broussard #1 well in the Constitution field. Please provide the production graph of oil and gas over time with the future forecasted production annotated on the curve. Also provide a pressure versus cumulative production curve and a well head pressure versus time curve for this well. Provide any other technical data that support your reserve estimate. |
The requested technical documentation that supports the gas reserves attributed to the Paggi-Broussard #1 well in the Constitution field has been supplementally submitted to Mr. Murphy.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 10
For the 2004 and 2005 reserve report, we consulted Fekete Associates, Inc. to prepare a Rate Transient Analysis. This analysis was prepared to determine reservoir limits and original gas in place. The volumetric calculations of the reservoir volume, conforming to the well controlled net pay and structure maps was included in the submission to Mr. Murphy.
18. | We note that in the Elm Grove field your working interest in the proved producing wells appears to average around 2 or 3% while in the proved non-producing wells your working interest averages higher and in the proved undeveloped wells higher still. Please explain this to us. |
As referenced in our response to comment #14, we acquired our position in Elm Grove Field in the fourth quarter 2004. The acquired assets include varied working interest ownership in several sections. The majority of acquired producing assets were on leases operated by Camterra, JW Operating, and Questar. Our ownership in these leases is relatively low, ranging from less than 1% to 5%. Fewer of the acquired producing assets were on the leases operated by WSF (now operated by Petrohawk) where we possess higher working interest, ranging from 18% to 37%. Thus, our average working interest on the producing properties was originally, and is currently low in relation to our average working interest on the leases. However, the recent drilling activity and remaining undrilled proved locations are more prevalent on the higher ownership leases. Thus, the relationship of lower interest producing properties, higher interest non-producing entities, and higher still proved undeveloped wells is dictated by the leasehold ownership of each specific entity. When preparing the year end 2004 and 2005 reserve reports, the ownership of each entity was reviewed and verified against our underlying lease records.
19. | We note frequently in the reserve reports certain quantities of negative investments under the proved producing properties. Please explain to us what these represent and if they are also included in the other reserve categories. |
We evaluate the Salvage and Abandonment for each well and assign capital estimates in our reserve database. In instances where the salvage estimate exceeds the abandonment estimate, the difference is reflected as a negative investment at the end of the economic life. Frequently the abandonment estimate exceeds the salvage estimate and a positive net investment is accounted for at the end of commercial life of the property. Please note that the total net capital investment listed in the reserve report for the producing properties is over $12 million, indicating that our estimated abandonment costs substantially exceed our salvage estimate. The Salvage and Abandonment estimate is accounted for on the final Proved Case, and therefore, these capital estimates do affect the other reserve categories.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 11
20. | We note significant investments, up to one third to one half of the cost of a new well, required under some wells classified as having proved non-producing reserves. We believe that wells with this level of remaining investment should be classified as proved undeveloped. Please revise your document or tell us why it is not necessary. Please explain how this was reconciled with Ryder Scott. |
In our reserve database, Proved Developed Non-Producing capital costs are typically substantially less than drill well costs. Technical information that illustrates that the capital costs are generally not significant in relation to the costs to drill the wells has been supplementally submitted to Mr. Murphy.
One notable error in our database is reflected on the highest value PDN case, the ESDU3PDN0040 WATERFLOOD case at SHUGART EAST (DELAWARE) Field. Although wells had been drilled and completed at year end, our database included the capital related to the costs to drill and complete the wells. Even though it is an error, it is conservative because substantial capital is modeled that will not be required to produce these reserves. The ESDU error result was including an additional $4.0MM of capital.
Additionally, nine proved developed non-producing wells have been recently drilled and were waiting on completion at yearend. In these cases, although the remaining completion cost estimates were equivalent to the completion estimate, we erroneously included a portion of the drilling cost estimate as well as the completion cost estimate in our database. These are isolated incidents and based on the dollar amount involved, it does not materially impact the PV-10 value and it has no impact on the reserve volumes. The result was including an additional $1.8MM of capital, thereby reducing the undiscounted PV-10 by this similar amount since the capital costs were in the early years.
In future instances where a portion of the drilling cost and the completion cost are required to complete the well, we will categorize those entities as proved undeveloped reserves.
In some Elm Grove wells, we currently do not have ownership in the currently completed intervals. We do hold ownership in uphole intervals, but in addition to recompletion costs, we will be required to pay a well cost adjustment to account for drilling costs. These are very low value entities with insignificant reserve implications; we will modify our methodology to account for these wells as proved undeveloped reserves in future evaluations.
Because we strongly believe that capital cost estimates for our proved developed non-producing cases are not abnormally significant in relation to drill well costs, we have not
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 12
perceived that it has been necessary to reconcile this issue with Ryder Scott Company. We believe that Ryder Scott Company recognizes our diligent attempts to accurately reflect capital and operating costs.
* * * * * * * * * * * * * * * * * * * * *
In connection with our responses to the Staff’s comments, the Company acknowledges that:
| • | the Company is responsible for the adequacy and accuracy of the disclosure in the filing; |
| • | staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and |
| • | the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States. |
Thank you for your consideration of our explanations and our proposal to enhance future disclosures.
Please contact me at (303) 863-4334 with any further questions.
Best Regards,
David W. Honeyfield
V.P. – Chief Financial Officer, Secretary & Treasurer
cc: | James Murphy, SEC Petroleum Engineer |
Dwight Landes, Ballard Spahr Andrews & Ingersoll, LLP
| Dennis Boylan, Deloitte & Touche, LLP |
